1. Field of the Invention
This invention relates broadly to apparatus and processes for recovering fluid by injection of hot vapor or other heat assisted production techniques. More particularly, this invention relates to apparatus and processes for recovering natural bitumen and other forms of heavy oil by heat assisted production techniques.
2. Description of Related Art
There are many petroleum-bearing formations from which oil cannot be recovered by conventional means because the oil is so viscous that it will not flow from the formation to a conventional oil well. Examples of such formations are the bitumen deposits in Canada and in the United States and the heavy oil deposits in Canada, the United States, and Venezuela. In these deposits, the oil is so viscous, under the prevailing temperatures and pressures within the formations, that it flows very slowly (or not at all) in response to the force of gravity. Heavy oil is an asphaltic, dense (low API gravity), and viscous oil that is chemically characterized by its contents of asphaltenes (very large molecules incorporating most of the sulfur and perhaps 90 percent of the metals in the oil). Most heavy oil is found at the margins of geological basins and is thought to be the residue of formerly light oil that has lost its light-molecular-weight components through degradation by bacteria, water-washing, and evaporation. Natural bitumen (often called tar sands or oil sands) shares the attributes of heavy oil but is yet more dense and more viscous.
Heavy oil is typically recovered by injecting super-heated steam into the reservoir, which reduces the oil viscosity and increases the reservoir pressure through displacement and partial distillation of the oil. Steam may be injected continuously utilizing separate injection and production wells. Alternatively, the steam may be injected in cycles so that a well is used alternatively for injection and production (the so called “huff and puff” process).
Natural bitumen is so viscous that it is immobile in the reservoir. For oil sand deposits less than 70 meters deep, bitumen is recovered by mining the sands, then separating the bitumen from the reservoir rock by hot water processing, and finally upgrading the natural bitumen to synthetic crude oil. In deeper bitumen deposits, steam is injected into the reservoir in order to mobilize the oil for recovery. The product may be upgraded onsite or mixed with dilutent and transported to an upgrading facility.
FIGS. 1A and 1B illustrate a system for recovery of oil from a reservoir of natural bitumen. This system, which is commonly referred to as a steam-assisted gravity drainage system, employs a stacked pair of horizontal wells disposed in a reservoir 2 of natural bitumen which is typically sandwiched between a top layer of caprock 4 and a bottom layer of shale 6. The upper well 8, referred to as the injection well, is used to inject a hot vaporized fluid (such as steam and/or a solvent vapor) into the bitumen reservoir 2. The hot vaporized fluid heats the formation and mobilizes the bitumen. Gravity causes the mobilized bitumen to move toward the lower well 10, referred to as the production well, as shown in FIG. 1B. The bitumen fluid is then pumped by an artificial lift system to the surface through the production well 10.
Recent advances in electrical submersible pump (ESP) designs (such as the HOTLINE ESP commercially available from Schlumberger) are capable of operation in the expected temperature ranges (e.g., greater than 205° C.) of many heat assisted production techniques including the steam-assisted drainage system of FIGS. 1A and 1B for bitumen recovery. However, the downhole ESP can be damaged (or its operational lifetime adversely impacted) by the periodic direct breakthrough of injection vapor, which is referred to herein as “injection vapor breakthrough.” The injection vapor is commonly supplied to the injection well 8 at a temperature on the order of 260° C. When injection vapor breakthrough occurs, injection vapor enters the production well without experiencing significant cooling relative to its hot temperature as supplied to the injection well. The high temperature of the injection vapor breakthrough can damage the downhole ESP when it is running and/or can adversely impact its operational life.
Similar problems can be experienced by surface equipment, such as a multiphase flow meter. The multiphase flow meter continually measures the individual phases of the production fluid without the need for prior separation, which allows for quick and efficient well performance trend analysis and immediate well diagnostics. Such multiphase flow meters can be damaged, or their operational life shortened significantly, by the high temperatures that result from injection vapor breakthrough.
Thus, there remains a need in the art to provide mechanisms that protect downhole equipment and surface equipment from the high temperatures that result from the breakthrough of injection vapor in heat assisted production applications.